1. Area of the Invention
The present invention relates to deep-set safety valves used in subterranean well production. More specifically, the present invention relates to deep-set safety valves used in connection with submersible pumps for controlling a well.
2. Description of the Related Art
In subsurface wells, such as oil wells, an electrical submersible pump with a motor (an “ESP”) is often used to provide an efficient form of artificial lift to assist with lifting the production fluid to the surface. ESPs decrease the pressure at the bottom of the well, allowing for more production fluid to be produced to the surface than would otherwise be produced if only the natural pressures within the well were utilized.
There may be times when an operator of a well would want or need to retrieve an ESP from within the well. In order to do so, the operator must have a means for closing off the well so that the production fluid does not still flow to the surface, while the ESP is retrieved. Killing the well may be accomplished by pumping heavy fluids into the well to overbalance the subterranean pressure. But that method can cause formation damage so it is therefore more desirable to control the well than to kill it. Maintaining control of a well with an umbilical-deployed ESP would normally require the use of a deep set subsurface safety valve (SSSV) or other shut-off valve that would be set below the ESP to shut-in the well first so that the ESP could be retrieved. Normally deep-set safety valves are controlled via a single ¼″ OD hydraulic umbilical to the surface, but at deep depths, the hydraulic pressures are very high and even when the hydraulic system fails, the magnitude of residual hydraulic pressure can be significant. In such a system, the springs that return the valve to the closed position must be capable of overcoming the residual hydrostatic pressure in order to shut-in the well in an emergency situation. Therefore, the deeper the well, the higher the pressure, and the stronger the spring system must be to lift the hydraulic fluid column to close the valve and shut-in the well. There will also come a point when the hydraulic pressures would be so great that a spring system would become very difficult to implement and eventually become unfeasible. Springs can generally be constructed as either plain mechanical or mechanical plus gas-charge assisted.
One way to solve this deep setting problem is to use an electrically activated subsurface safety valve (E-SSSV). E-SSSVs are usually powered via a ¼″ tubing encased conductor (TEC) which is a hydraulic umbilical with one or more electric wires inside, Electrical wet connectors can be a source of failure in a well system and can be cumbersome to work with so it would be advantageous for a system to operate without the need for a wet connector if the components that activate the E-SSSV need to be retrieved, for example, for maintenance or repair.
Also, a typical failure mode of most flapper-type safety valves is the flow tube becomes stuck to the valve mandrel, sticking the valve open. This is because typical deep-set safety valve systems do not have excessive force available to push the flow tube upward and free it from wellbore contaminants such as asphaltines, scale, and packed fines.
Prior art safety valves are configured in only two methods; either wireline retrievable or tubing retrievable. Both the prior art hydraulic and electrical safety valves are provided with a dedicated method of control, that is, the connection between the surface and the valve is not shared with any other downhole component. This creates additional time and cost associated with requiring multiple connection components and may also raise design issues in finding space to route multiple control lines downhole.
Some prior art flapper safety valves also require the pressure to be equalized on either side of the valve before it can be opened. This requires passageways that connect the space above and below the flapper. This in turn creates additional components, including a valve means for opening and closing this passageway and a means for activating such valve. It would be advantageous to avoid the need for such equalization.
In addition, with the prior art methods, normally the well must be killed and a full rig used to pull the tubing string when an ESP replacement is required. It would be advantageous to neither to kill the well, nor require a rig to replace an ESP completion.
Therefore a problem exists of how to provide fail-safe well control for a live well intervention on an assisted ESP artificial lift, which was umbilical deployed.